Downhole drilling system

ABSTRACT

The present invention relates to a downhole drilling system, comprising: a drill string having a drill head configured to drill a borehole having a borehole wall forming an annulus between the drill string and the borehole, a plurality of sensor units forming a mesh network, wherein each one of said sensor units is distributed in a drilling fluid flowing in the annulus and in the drill string, and at least one of said sensor units is provided with a detector for measuring position data. The present invention also relates to a method for providing a downhole drilling system according to the present invention and to a method for determining drilling direction.

DESCRIPTION

The present invention relates to a downhole drilling system, to a methodfor providing a downhole drilling system according to the presentinvention and to a method for determining drilling direction.

Wells are formed by drilling a borehole in the ground for retrievinge.g. natural gas or petroleum. Depending on the formation to be drilled,various concerns need to be taken into account such as e.g. the drillingtechnique, the drill bit to be used, the actual structure of theformation etc.

During drilling, a drilling fluid, in particular a drilling liquidcommonly denoted “drilling mud”, is used to assist in the drillingprocess. The use of drilling mud provides a lower density fluid in thedrilled borehole, whereby formation fluids are prevented from flowinginto the borehole. Also, the drilling fluid is preferably selected inorder to provide efficient cooling and cleaning of the drill bit.

The drilling fluid is normally conducted by the drill string carryingthe drill bit, and apertures in the drill string will allow the drillingfluid to flow into the borehole for achieving the functionalitiesmentioned above. As cuttings are released downhole, these are carriedupwards by the flow of the drilling fluid through the annular spacebetween the drill string and the drilled borehole until they reach thesurface. Hence, recirculation of the drilling fluid is possible.

The shape of the borehole is defined by a bottom hole assembly, formingthe most distal part of the drill string. The bottom hole assembly maybe equipped with one or more tools for performing measurement whiledrilling (MWD). These tools are configured to measure properties of thedrilling process, such as the trajectory of the borehole.

The MWD tools provide data to the surface, preferably via mud pulsetelemetry, whereby an operator can evaluate the drilling process.However, the bandwidth of mud pulse telemetry drops rapidly withincreasing well depth, and transmitting mud pulses may, in suchsituations, require interruption of the drilling process.

In order to solve these problems, it has been suggested to useelectromagnetic telemetry. However, also this technique shows somelimitations in terms of signal strength, especially for deep wells.

In view of the above, it would be advantageous to provide a solutionallowing for measurements of the drilling process while ensuringsufficient signal strength and bandwidth, also for exceptionally deepwells.

It is an object of the present invention to wholly or partly overcomethe above disadvantages and drawbacks of the prior art. Morespecifically, it is an object to provide an improved method and systemfor real time measurements of the drilling process.

Thus, it is also an object to provide an improved method and system forreal time communication with the drill head for adjusting the drillingprocess, e.g. the drilling direction.

The above objects, together with numerous other objects, advantages andfeatures, which will become evident from the below description, areaccomplished by a solution in accordance with the present invention by adownhole drilling system, comprising:

a drill string having a drill head configured to drill a borehole havinga borehole wall forming an annulus between the drill string and theborehole,

a plurality of sensor units forming a mesh network,

wherein each one of said sensor units is distributed in a drillingfluid, said drilling fluid flowing in the annulus and in the drillstring, and at least one of said sensor units is provided with adetector for measuring position data of said sensor unit.

Thus, the plurality of sensor units forming a mesh network provides fora reliable data path even though at least some of the sensor units areout of range from the data collection provided at surface or at seabedlevel.

All sensor units may be provided with a detector for measuring positiondata.

The detector may comprise an accelerometer and/or a magnetometer, andposition data may comprise inclination and/or azimuth.

The downhole drilling system according to the present invention mayfurther comprise a sensor module comprising additional sensors.

Said sensor module may comprise a temperature sensor and/or a pressuresensor.

Moreover, each sensor unit may be configured to receive wirelesslytransmitted data from an adjacent sensor unit, and to forward thereceived data to the adjacent sensor units.

The downhole drilling system as described above may further comprise asurface system configured to receive downhole data from said sensorunits.

The surface system may be at least partly arranged at the seabed level.

Also, said surface system may further be configured to determine theposition of at least one sensor unit in relation to the surface system,and to associate said determined relative position with associatedposition data.

Further, the surface system may be configured to determine the relativeposition of at least one sensor unit by Monte Carlo simulation and/orShortest Path simulation.

The present invention also relates to a method for providing a downholedrilling system as described above, said method comprising:

entering a plurality of sensor units in a drilling fluid, and

entering said drilling fluid in a borehole annulus via a drill stringduring drilling, whereby each sensor unit is positioned in said annulus.

Each sensor unit may be flowing randomly in said annulus.

The present invention further relates to a method for determiningdrilling direction, comprising:

providing a downhole drilling system by performing the method forproviding a downhole drilling system as described above,

activating at least one sensor unit for measuring position data of saidsensor unit,

transmitting data corresponding to said measured position data from theactivated sensor unit to a surface system via at least one adjacentsensor unit, and

analysing the received data in order to determine the drillingdirection.

Said method for determining drilling direction may further comprisedetermining the position of said activated sensor unit in relation tothe surface system, and associating said determined relative positionwith the corresponding position data received by said surface system.

Moreover, activating at least one sensor unit may comprise measuringinclination and/or azimuth.

The method for determining drilling direction may further comprisecomparing the determined drilling direction with an intended drillingdirection, and optionally adjusting the current drilling direction basedon the comparison.

It should be noted that within this specification, the term “meshnetwork” should be interpreted as a network of which each associatedsensor forms a network node being configured to relay data for thenetwork. All network sensors thus cooperate in the distribution of datain the network. In a mesh network within the context of thisspecification, data transfer is accomplished by routing data between thesensors until the data reaches its destination. The data path is notconstant, but it is re-routed if any existing sensors are unavailable.

The invention and its many advantages will be described in more detailbelow with reference to the accompanying schematic drawings, which forthe purpose of illustration show some non-limiting embodiments and inwhich:

FIG. 1 shows a drilling operation according to prior art,

FIG. 2 shows a drilling operation according to an embodiment,

FIG. 3 is a schematic view of a drilling system according to anembodiment,

FIG. 4 is a schematic view of a sensor unit for use with a drillingsystem according to an embodiment,

FIG. 5 is a diagram showing data communication between different sensorunits of a drilling system according to an embodiment,

FIG. 6 is a schematic view of a method of providing a downhole drillingsystem according to an embodiment,

FIG. 7 is a schematic view of a method of determining drilling directionaccording to an embodiment,

FIG. 8 is a schematic view of a self-powering device of a sensor unit,and

FIG. 9 shows a cross-sectional view of a drilling system.

All the figures are highly schematic and not necessarily to scale, andthey show only those parts which are necessary in order to elucidate theinvention, other parts being omitted or merely suggested.

FIG. 1 schematically shows a drilling operation according to prior artsolutions. A drill string DS is provided for drilling a borehole in anunderground formation F from a surface level S. The distal end of thedrill string DS is equipped with a drill bit DB configured tomechanically cut through the formation. As the diameter of the drill bitDB is larger than the diameter of the drill string DS, an annulus A willbe formed between the drill string DS and the walls W of the borehole.During drilling, a drilling mud DM is provided at the drilling area,i.e. at the current position of the drill bit DB. As drilling isperformed, the drilling mud DM will flow upwards through the annulus Aback to the surface level S. The drilling mud DM can then bere-circulated back to the drill string DS, optionally after intermediatecleaning or modification of the used drilling mud DM.

Now turning to FIG. 2, a drilling process according to an embodiment ofthe present invention is schematically shown. Although the generalprinciple of drilling is identical to the process shown in FIG. 1, asignificant difference is that a drilling fluid 5, e.g. drilling mud, isprovided with a plurality of individual sensor units 10 which areconducted by the drilling fluid along the drilling string and outthrough the drill head/bit 6 and along the annular space to surfacelevel 60 or seabed level. Each sensor unit 10 is positioned arbitrarilyin the flowable drilling fluid 5, e.g. drilling mud, and thedistribution of sensor units 10 is thus random. As the drilling fluidflows in the annulus 4 around the drill bit 6 and the drill string 1,the sensor units 10 will follow the drilling fluid as it flows upwardsand towards the surface level 60. The position of the sensor units 10will thus not be fixed, but instead randomly distributed in the annulus4 both in the axial direction, i.e. the longitudinal extension of theborehole 2, in the radial direction, and in the circumferentialdirection. Preferably, the drilling fluid 5 is supplied through thedrill string 1 and enters the annulus 4 via one or more outlet ports 7.These ports may be arranged at the drill bit 6, as illustrated in FIG.2. Thus, the sensor units change position over time along with thedrilling fluid.

The sensor units 10 are entered in the drilling fluid in order to form“smart drilling mud”, i.e. to provide information to the surfacerelating to the drilling direction over time, i.e. during the entiredrilling process as long as drilling fluid 5 is present. As will beexplained in the following, this is realised by configuring the sensorunits 10 to establish a physically distributed independent and localisedsensing network, i.e. a mesh network, preferably with peer-to-peercommunication architecture. As will be understood from the followingdescription, the mesh network being established by the sensor units 10,as a self-healing mesh network, will automatically provide for areliable and self-healing data path, even though at least some of thesensor units 10 are out of range from the final destination, i.e. thedata collection provided at the surface level 60. In this way, a veryreliant communication network is established which is independent of thedepth of the borehole, since the sensor units communicate with theadjacent sensor unit communicating again with the adjacent sensor unitall the way up and down the well while drilling.

All sensor units 10 are preferably identical, although provided with aunique ID. An example of a sensor system, i.e. a drilling system 100, isschematically shown in FIG. 3. The drilling system 100 comprises asurface system 110 and a sub-surface system 120. The sub-surface system120 comprises a plurality of sensor units 10, although only one sensorunit 10 is shown in FIG. 3. Each sensor unit 10 is provided with anumber of components configured to provide various functionality to thesensor unit 10. As shown in FIG. 3, each sensor unit 10 includes a powersupply 11, a digital processing unit 12, a transceiver 13, a detector14, and optionally a sensor module comprising additional sensors 15. Thesensor module may e.g. comprise a temperature sensor 15 a and/or apressure sensor 15 b (shown in FIG. 4). The detector 14, together withthe digital processing unit 12, form a detecting unit for determiningposition data of the sensor unit 10. In particular, the detector 14comprises an accelerometer 14 a and/or a magnetometer 14 b (shown inFIG. 4).

For example, the accelerometer 14 a is configured to measure theinclination, or tilt angle, of the sensor unit 10 according to wellknown principles, while the magnetometer 14 b is configured to measurethe azimuth, or projected angle, of the sensor unit 10. The measuredinclination and/or the azimuth form/forms position data. The digitalprocessing unit 12 is configured to receive the position data and toperform various analysing algorithms in order to provide an outputrepresenting the current position of the sensor unit 10. Alternatively,the analysing algorithms are provided at the surface level, i.e. bymeans of the surface system 110.

As the sensor units 10 are in motion due to the flow of the drillingfluid 5, the digital processing unit 12 may be configured to apply acompensation algorithm to the position data in order that the exactorientation of the sensor unit 10 does not affect the resulting positiondata value. Hence, such compensation algorithm could e.g. be programmedto calculate a delta position, i.e. calculate a change in position froma previously determined position. The position data determined by meansof the detector 14 may therefore represent the motion of the sensorunits 10, rather than the exact position.

As is evident, different algorithms may be used in order to determinethe trajectory of the borehole during drilling. For example, each sensorunit 10 may be programmed to measure position data continuously, or atgiven sample intervals. These intervals may be pre-set and dependent onthe flow rate of the drilling fluid 5 in order to ensure sufficientresolution of the detected position data. As the sensor units 10 willflow into the borehole, and change its flowing direction when they exitthe drill string, it may be possible to detect this change in directionand determine the associated position data (i.e. the inclination andazimuth) at this point in time. Accordingly, as this position data ismeasured at the longitudinal end of the borehole, the trajectory of theborehole can be determined.

The power supply 11 is configured to supply power to the othercomponents 12-15 of the sensor unit 10, either by means of an internalpower storage, such as one or more batteries, or by converting energy ofthe surrounding fluid to electrical energy and thus the power supply 11may be in the form of a self-powering device. For the latter, the powersupply 11 may include a piezo element being configured to convertmechanical vibrations of the surrounding fluid, i.e. drilling fluid, toelectrical energy. Optionally, a capacitor may be included in the powersupply 11 for temporarily storing harvested energy. As the sensor units10 are arranged in a moving fluid, it is also possible to provide thepower supply with a generator converting mechanical motion to electricalpower. Such generator may e.g. include a turbine or similar.

In FIG. 8, the self-powering device 11 is shown in further detail. Theself-powering device 11 is configured to provide electrical power to thevarious electrical components of the sensor unit by harvesting energyfrom the downhole environment while flowing in the drilling fluid. Theself-powering device 11 therefore comprises an energy harvesting module1100. The harvesting module 1100 may be selected from the groupcomprising a vibrating member 1101, a piezoelectric member 1102, amagnetostrictive member 1103, and a thermoelectric generator 1104. As isshown in FIG. 8, any of these members is possible. In case of using avibrating member 1101, a piezoelectric member 1102, or amagnetostrictive member 1103, the energy harvesting module 1100 isconfigured to convert mechanical vibrations of the surroundingenvironment, such as in the downhole fluid or drilling fluid, toelectrical energy. In case of using a thermoelectric generator 1104,such as a Peltier element, the harvesting module 1100 is configured toconvert thermal energy of the surrounding energy to electrical energy.

The harvested energy is preferably supplied to a rectifier 1105. Therectifier 1105 is configured to provide a direct voltage and comprises aswitching unit 1106 and a rectifier 1107. It should be noted that theposition of the switching unit 1106 and the rectifier 1107 could bechanged, in order that the rectifier 1107 is directly connected to theharvesting module 1100. As is shown in FIG. 8, the rectifier 1107 ispreferably connected to a capacitor 1108 for storing the harvestedenergy. The electrical components 12-15 of the sensor unit are thereforeconnected to the capacitor 1108 to form the required power source orstorage buffer. Optionally, the self-powering device 11 is furtherprovided with an amplifier (not shown), and/or with control electronics(not shown) for the switching unit 1106. Additional capacitors may alsobe provided.

In FIG. 3, the digital processing unit 12 comprises a signalconditioning module 21, a data processing module 22, a data storagemodule 23 (STORAGE in FIG. 3), and a micro controller 24. The digitalprocessing unit 12 is configured to control operation of the entiresensor unit 10, as well as temporarily storing sensed data in the memory23 of the data storage module 23.

The transceiver 13 is configured to provide wireless communication withtransceivers of adjacent sensor units 10. For this, the transceiver 13comprises a radio communication module and an antenna. The radiocommunication module 13 may be configured to communicate according towell-established radio protocols, e.g. IEEE 801.1aq (Shortest PathBridging), IEEE 802.15.4 (ZigBee) etc. The radio communication modulemay also be configured to position the sensor units in relation to eachother, i.e. configured to perform a distance measurement. In this way, avery reliant communication network is established which is independentof the depth of the borehole, since the sensor units communicate withthe adjacent sensor unit communicating again with the adjacent sensorunit all the way up and down the well while drilling.

The surface system 110 also comprises a number of components forproviding the desired functionality of the entire drilling system 100.As is shown in FIG. 3, the surface system 110 has a power supply 31 forproviding power to the various components. As the surface system 110 maybe permanently installed, the power supply 31 may be connected to mainspower, or it may be formed by one or more batteries. The surface system110 also comprises a transceiver 32 for receiving data communicated fromthe sensor units 10, and also for transmitting data and control signalsto the sensor units 10. Hence, the transceiver 32 is provided with aradio communication module and an antenna for allowing communicationbetween the surface system 110 and the sensor units 10 of thesub-surface system 120. The surface system 110 also comprises a clock33, a human-machine interface 34, and a digital processing unit 35. Thedigital processing unit 35 comprises the same functionality as thedigital processing unit 12 of the sensor unit 10, i.e. a signalconditioning module, a data processing module, a data storage module,and a micro controlling module.

Before describing the operation of the drilling system 100, a sensorunit 10 is schematically shown in FIG. 4. The sensor unit 10 has ahousing 19 which is configured to enclose the components previouslydescribed, as well as to form a protective casing which is capable ofwithstanding any impact with the drilling fluid and/or withstandingpotential collisions with the borehole wall or the drill string.Although shown as rectangular, the shape of the housing 19 may of coursebe chosen differently. For example, it may be advantageous to providethe housing 19 with only rounded corners. The housing 19 may for suchembodiment have a spherical shape. Inside the housing 19, the followingis fixedly mounted: the power supply 11, the digital processing unit 12,the transceiver 13, the detector 14, and optionally the sensor module,e.g. additional sensors 15, 15 a, 15 b. These components are preferablythe same as those described with reference to FIG. 3, i.e. the detector14 preferably comprises an accelerometer 14 a and/or a magnetometer 14b.

Now turning to FIG. 5, the configuration of the drilling system 100 willbe described further, and in particular the downhole or sub-surfacesystem 120 will be described. The sensor units 10A-F, representing partsof a sub-surface system 120, are randomly distributed in the annuluswhile flowing with the drilling fluid DM. The communication between thesensor units 10A-F is preferably based on a relay model, which meansthat the surface system communicates with the sensor units 10A-F via asensor unit network. Preferably, each signal that is transmitted from asensor unit 10A-F comprises information relating to a unique ID of thesensor unit 10A-F. Further, data echoing and cross-talk are reduced bylimiting the number of possible re-transmissions between the sensorunits 10A-F. By reducing data echoing, the possibility of one sensorunit sending the same data more than once to the same neighbouringsensor unit is eliminated. The network knows its neighbours by theirunique IDs, and hereby the transmitter can target the transmission ofdata, and thus the situation in which data is sent back and forth can beavoided in that the neighbouring sensor unit “knows” from which sensorunit the data is received and it will consequently not send that databack again.

Each sensor unit 10A-F is preferably configured to operate in twodifferent modes. The first mode, relating to activation for the purposeof receiving data relating to the position, or trajectory of theborehole, preferably comprises a step of gathering data (optionallyincluding data from the additional sensors 15, 15 a, 15 b shown in FIG.4), and to transmit the data upon request. In the second mode, thesensor units 10A-F are configured to re-transmit received signals.

The axial location of each sensor unit 10A-F may also be determined by around-trip elapsed time measured by the surface system 110. The surfacesystem 110 may thus be configured to ping a specific sensor unit 10A-Fusing the unique ID, whereby the specific sensor unit 10A-F replies bytransmitting a response signal with a unique tag. The surface system 110receives the transmitted signal with elapsed times, and either MonteCarlo simulation and/or Shortest Path simulation may be used todetermine the specific position of the sensor unit 10A-F.

Using Monte Carlo simulation, a simulated sensor unit location model maybe created having a uniform probability distribution. For such method,it may be possible to assume that the sensor units 10A-F are randomlydistributed over a specific borehole length, and that these locations,for a given time, are known in the simulated model. The simulated modelalso includes a relay model with specific individual sensor processingdelays.

For each distribution, the shortest round-trip travel time is calculatedfor each of the sensor units 10A-F. This results in a map of travel timeversus location of sensor units 10A-F. It is then possible to comparethe measured elapsed time with the map to determine the location of thesensor units 10A-F. The number of sensor units 10A-F may preferably beselected in order that it is likely that at any given time, at least onesensor unit 10A-F will be positioned at the end of the borehole (i.e. atthe position closest to the drill bit 6). Once it has been determinedwhich sensor unit 10A-F is arranged at this position (e.g. by selectingthe sensor unit(s) 10A-F being most remote from the surface system 110),it is possible to fetch the position data measured by the determinedsensor units 10A-F at this point in time, and to determine theinclination and the azimuth from these data in order to obtain thecorrect trajectory of the drilling operation.

For Shortest Path simulation, once the surface system 110 pings a sensorunit 10A-F, the round-trip times of multiple received signals, each onefrom a specific relay path, are recorded. The shortest time for theparticular sensor unit 10A-F is then determined by calculating thedistance from the surface system 110 using the speed of light.

In the example shown in FIG. 5, each sensor unit 10A-F forms a node inthe mesh network 130. Each node is configured to receive and transmitdata signals, as well as adding ID and timestamp with each data package.Each node will send a signal corresponding to its current state (i.e.the detected signals representing cement characteristics) asynchronouslywith respect to other nodes. In the table below, data communication inthe mesh network 130 is explained further. In the table, nX representsthe node ID, TnX represents the timestamp for the particular node, andsX represents the sensed data from the particular node.

Node Forwarded signal Received signal 10A nA:TnA:sA 10B nB:TnB:nA:TnA:sAnA:TnA:sA 10C nC:TnC:nA:TnA:sA nA:TnA:sA 10D nB:TnB:nA:TnA:sAnC:TnC:nA:TnA:sA nD:TnD:nB:TnB:nA:TnA:sA nD:TnD:nC:TnC:nA:TnA:sA 10EnB:TnB:nA:TnA:sA nC:TnC:nA:TnA:sA nE:TnE:nB:TnB:nA:TnA:sAnE:TnE:nC:TnC:nA:TnA:sA nD:TnD:nB:TnB:nA:TnA:sA nD:TnD:nC:TnC:nA:TnA:sAnE:TnE:nB:TnB:nA:TnA:sA nE:TnE:nC:TnC:nA:TnA:sA

Accordingly, data is communicated through the mesh network 130 until thesignals are received by the surface system 110.

Now, with reference to FIG. 6, a method 200 for providing the downholedrilling system 100 will be described. The method 200 is performed by afirst step 202 of providing a plurality of sensor units 10, and byentering these sensor units 10 in a drilling fluid. In a subsequent step204, the drilling fluid, e.g. drilling mud, having sensor units 10therein is conducted by the drill string, having a drill bit/head 6arranged downhole in a borehole. In a following step 206, the drillingoperation is started, in which the drill bit/head will be activated todrill downhole. During this step, the drilling fluid will flow downholethrough the drill string, and exit close to the position of the drillbit, thereby flowing out in the annulus formed between the borehole walland the drill string. In step 208, the sensor units 10 will thereby bedistributed randomly in the annulus as they flow upwards with thedrilling fluid and the generation of the mesh network can be initiatedas described below.

As explained above, the sensor units 10 are activated to monitor anddetermine position data corresponding to the trajectory of the boreholeand thus also the position of the drill head/bit. A method 300 performedfor the purpose of such monitoring is schematically shown in FIG. 7. Asthe method 300 requires the provision of a downhole drilling system,initially the method 200 described above is performed.

Additionally, in step 302 a surface system 110 is provided. The surfacesystem 110, described above with respect to FIG. 3, is configured tocommunicate with the sub-surface system 120, i.e. the drilling systemprovided by performing the method 200, and comprises the downhole sensorunits 10 flowing with the drilling fluid.

In step 304 “linking”, the surface system 110 is linked to thesub-surface system 120. Linking is preferably performed duringconfiguration and programming of the respective sensor units 10 as wellas the surface system 110, and step 304 may thus correspond to aconfirmation step. As described above, step 304 may be performed bysending a verification signal from the surface system 110, andrequesting replies from each sensor unit 10. Once the replies arereceived, the drilling system 100 is verified and it is ready foroperation. Each reply signal is routed via the sensor units 10 inaccordance with the description relating to FIG. 5. The sensor units 10thus form a mesh network.

During operation of the drilling system 100, at least one of said sensorunits 10 is activated in step 306. Activation may either occur as aresponse to a control signal transmitted from the surface system 110, orthe sensor units 10 may be programmed to be activated at pre-determinedtime intervals. For example, each sensor unit 10 may be programmed to“wake up” at specific times, such as every 10 seconds, every one minuteetc. Determining the time intervals between subsequent activations maypreferably be done prior to arranging the sensor units 10 downhole, orby transmitting a control signal from the surface system 110. When asensor unit 10 is activated, in step 308 it measures the currentposition, e.g. the inclination and the azimuth, by means of thedetector. The detected data is preferably processed by the sensor unit10, e.g. by executing one or more of the above mentioned position dataalgorithms, and the resulting data, corresponding to position data, istransmitted by means of the wireless transceiver. As is evident, duringactivation further parameters may be measured as well, such astemperature and/or pressure, and data corresponding to such measurementsmay be included in the transmitted signal in step 308.

As the data signal is transmitted, the method 300 includes a step 310 ofrouting the data signal in order that it eventually reaches the surfacesystem 110. If the sensor units 10 are distributed the entire way up tothe location of the surface system 110, routing may be achieved entirelyby the sensor units 10. However, in some cases the drill string may bearranged in a sealed-off part of the borehole, in order that thedrilling fluid is only present in this sealed-off part. In such case, adata collecting tool may be provided downhole, either temporarily orpermanently, to receive the routed data signals and forward the receiveddata signals to the surface system 110, either by wire or wirelessly.

Each sensor unit 10 is therefore programmed to, upon activation, alsolisten for transmitted signals and, upon receiving an alreadytransmitted signal, re-send the signal. Any transmitted data signal willautomatically be routed through the mesh network until it is received bythe surface system 110. Efficient routing may e.g. be achieved byutilising a protocol as described in the above table, whereby any datasignal transmitted will not only contain the measured data, but alsocontain timestamps and information about which sensor units 10 are beingused for routing. Each sensor unit 10 is thereby configured to relaydata for the mesh network. In order to ensure the integrity of the datapath, the network formed by the sensor units 10 is configured to apply aself-healing algorithm, e.g. Shortest Path Bridging. Should one or moresensor units 10 for some reason be damaged or by other means becomenon-functional, the network is configured to automatically self-heal byre-routing the data to existing and functional data paths.

In step 312, the data signals are received by the surface system 110,and data processing may be performed in order to convert the informationof the data signal to readable values corresponding to the trajectory ofthe borehole.

Hence, in step 314 the data is analysed, which may also include acomparison with an intended drilling operation. The intended drillingoperation normally includes an intended trajectory of the borehole, andby analysing the measured data which indicates the actual trajectory, itis possible to provide real-time feedback and to make appropriateadjustments in the control of the drilling operation, i.e. the drive ofthe drill string and the associated drill bit. Such adjustment of thedrilling operation may be performed in step 316.

FIG. 9 discloses the downhole drilling system 100 in a partlycross-sectional view. As can be seen, the sensor units are conducted bythe drill string and flow with the drilling fluid 5 down to the drillhead 6 and out through the ports 7 into the annular space between thedrill string 1 and the borehole wall 3 and upwards to surface. Thesensor units are thus distributed all along the borehole 2, providing amesh network to provide real time measurements of the trajectory of theborehole and thus providing measurements of the direction in which thedrill head drills at present. Thus, the sensor units 10 provide realtime monitoring and communication from surface to the drill head toadjust the drilling direction in a much faster way than in the knownmethods and without the drilling process having to be stopped in orderto communicate or send measured data.

By drilling fluid or well fluid is meant any kind of fluid that may bepresent in oil or gas wells downhole, such as natural gas, oil, oil mud,crude oil, water, etc. By gas is meant any kind of gas compositionpresent in a well, completion, or open hole, and by oil is meant anykind of oil composition, such as crude oil, an oil-containing fluid,etc. Gas, oil, and water fluids may thus all comprise other elements orsubstances than gas, oil, and/or water, respectively.

In the event that the tool is not submergible all the way into thecasing, a downhole tractor can be used to push the tool all the way intoposition in the well. The downhole tractor may have projectable armshaving wheels, wherein the wheels contact the inner surface of thecasing for propelling the tractor and the tool forward in the casing. Adownhole tractor is any kind of driving tool capable of pushing orpulling tools in a well downhole, such as a Well Tractor®.

Although the invention has been described in the above in connectionwith preferred embodiments of the invention, it will be evident for aperson skilled in the art that several modifications are conceivablewithout departing from the invention as defined by the following claims.

1. A downhole drilling system, comprising: a drill string having a drillhead configured to drill a borehole having a borehole wall forming anannulus between the drill string and the borehole, a plurality of sensorunits forming a mesh network, wherein each one of said sensor units isdistributed in a drilling fluid, said drilling fluid flowing in theannulus and in the drill string, and at least one of said sensor unitsis provided with a detector for measuring position data of said sensorunit.
 2. A downhole drilling system according to claim 1, wherein allsensor units are provided with a detector for measuring position data.3. A downhole drilling system according to claim 1, wherein the detectorcomprises an accelerometer and/or a magnetometer, and position datacomprises inclination and/or azimuth.
 4. A downhole drilling systemaccording to claim 1, wherein at least one of said sensor units furthercomprises a sensor module comprising additional sensors.
 5. A downholedrilling system according to claim 4, wherein said sensor modulecomprises a temperature sensor and/or a pressure sensor.
 6. A downholedrilling system according to claim 1, wherein each sensor unit isconfigured to receive wirelessly transmitted data from an adjacentsensor unit, and to forward the received data to the adjacent sensorunits.
 7. A downhole drilling system according to claim 1, furthercomprising a surface system configured to receive downhole data fromsaid sensor units.
 8. A downhole drilling system according to claim 7,wherein said surface system is further configured to determine theposition of at least one sensor unit in relation to the surface system,and to associate said determined relative position with associatedposition data.
 9. A downhole drilling system according to claim 8,wherein the surface system is configured to determine the relativeposition of at least one sensor unit by Monte Carlo simulation and/orShortest Path simulation.
 10. A method for providing a downhole drillingsystem according to claim 1, said method comprising: entering aplurality of sensor units in a drilling fluid, and entering saiddrilling fluid in a borehole annulus via a drill string during drilling,whereby each sensor unit is positioned in said annulus.
 11. A methodaccording to claim 10, wherein each sensor unit is flowing randomly insaid annulus.
 12. A method for determining drilling direction,comprising: providing a downhole drilling system by performing themethod according to claim 10, activating at least one sensor unit formeasuring position data of said sensor unit, transmitting datacorresponding to said measured position data from the activated sensorunit to a surface system via at least one adjacent sensor unit, andanalysing the received data in order to determine the drillingdirection.
 13. A method according to claim 12, further comprising:determining the position of said activated sensor unit in relation tothe surface system, and associating said determined relative positionwith the corresponding position data received by said surface system.14. A method according to claim 12, wherein activating at least onesensor unit comprises measuring inclination and/or azimuth.
 15. A methodaccording to claim 12, further comprising comparing the determineddrilling direction with an intended drilling direction, and optionallyadjusting the current drilling direction based on the comparison.